Yuhao Zhu

A crosslinked hydroxypropyl guar (HPG) aqueous gel was investigated as the continuous, structure-forming phase of a CO₂-rich mixed-phase fracturing fluid for unconventional gas reservoirs. The CO₂ fraction was first screened by fluid-loss tests, after which the 30%, 40%, and 50% formulations were compared through proppant-settling tests. Although the 30% formulation exhibited the lowest cumulative fluid loss, the 40% formulation showed the lowest proppant-settling velocity and was selected for subsequent evaluation of phase behavior, gel-phase rheology, flow resistance, interfacial stabilization, and true-triaxial fracturing performance. Stable mixed-phase structures were maintained at 20–80 °C and 10–20 MPa, while bubble characteristics, rheology, and pipe-flow resistance showed a distinct response near 40 °C. Comparison with previously reported AM/AA–CO₂ visualization showed that different water-soluble polymers generated different structures after CO₂ mixing. Newly measured surface-tension and viscoelastic data, together with molecular dynamics simulations, indicated that bulk gel rheology alone could not account for this difference. HPG exhibited pronounced enrichment near the CO₂–water interfaces, whereas AM/AA remained predominantly within the aqueous phase. Combined with the component-removal and viscoelasticity results, these findings suggest that HPG-specific interfacial behavior contributes to the formation and organization of dispersed structures, while the crosslinked gel network provides additional bulk viscoelastic support.

CO₂ plume geothermal systems (CPGS) hold significant potential for geothermal energy extraction due to their dual benefits of carbon sequestration and efficient heat transfer. Existing studies primarily focus on macroscopic models of geothermal systems, with limited evaluation of real thermal reservoir cores in terms of CPGS heat extraction performance. This study investigates the seepage and heat transfer characteristics of CO₂ under various injection conditions through a combination of experiments and numerical simulations. Experimental results indicate that under the tested conditions, CO₂ exhibits 20–50% higher heat transfer capacity compared to distilled water. The heat transfer capacity increases with injection flow rate, while injection temperature shows a relatively limited influence under high-velocity seepage conditions. Specifically, at low injection flow rates, lower injection temperatures result in higher heat transfer capacity due to the increased thermal driving force between CO₂ and the reservoir rock. Microscale seepage-heat transfer simulations reveal that an increase in injection flow rate enhances CO₂ flow velocity within the pore network, expands the swept volume, and consequently strengthens convective heat transfer and increases the effective heat exchange area. Additionally, higher thermal reservoir temperatures establish a greater temperature gradient between the working fluid and rock, thereby enhancing heat transfer between CO₂ and the reservoir rock. The findings of this study provide valuable insights for optimizing CPGS design, particularly in understanding the impact of injection conditions on heat transfer capacity, with both practical engineering and theoretical implications.

Supercritical carbon dioxide (SC-CO₂) fracturing has emerged as an environmentally friendly alternative to conventional water-based hydraulic fracturing; however, its inherently low viscosity restricts proppant-carrying efficiency and reduces fracture conductivity. To address this limitation, this study systematically investigates the rheological behavior and sand-carrying mechanisms of CO₂ dry fracturing fluid under various thermodynamic and compositional conditions. Rheological measurements were conducted to evaluate the effects of thickener concentration, temperature, and pressure on viscosity, while visualized experiments were performed to examine the influence of injection rate, sand ratio, thickener concentration, and temperature on proppant migration and deposition. A numerical model developed in Fluent was further employed to simulate the temporal evolution of proppant transport within the fracture. The results show that higher thickener concentrations and injection rates significantly enhance proppant transport distance and uniformity, whereas elevated temperature and sand ratio promote localized settling. The simulation results agree well with the experimental observations, validating the model’s reliability. This study elucidates the coupled effects of rheology and operating parameters on CO₂ dry fracturing behavior and provides theoretical and experimental guidance for optimizing CO₂-based fracturing fluids in low-permeability reservoirs.

A CO₂-responsive TMPDA–SDS–SiO₂ gel system was developed and evaluated through formulation optimization, structural characterization, rheological testing, and core flooding experiments. The optimal formulation was identified as 7.39 wt% SDS, 1.69 wt% TMPDA, and 0.1 wt% SiO₂, achieving post-CO₂ viscosities above 10³–10⁴ mPa·s. Spectroscopic and microscopic analyses confirmed that CO₂ protonates TMPDA amine groups to form carbamate/bicarbonate species, which drive the micellar transformation into a wormlike network, thereby enhancing gelation and viscosity. Rheological tests showed severe shear-thinning behavior, excellent shear recovery, and reversible viscosity changes under alternating CO₂/N₂ injection. The gel demonstrated rapid responsiveness, reaching stable viscosities within 8 min, and maintained good performance after 60 days of thermal aging at 90 °C and in high-salinity brines. Plugging tests in sand-packed tubes revealed that a permeability reduction of 98.9% could be achieved at 0.15 PV injection. In heterogeneous parallel core flooding experiments, the gel preferentially reduced high-permeability channel conductivity, improved sweep efficiency in low-permeability zones, and increased incremental oil recovery by 14.28–34.38% depending on the permeability contrast. These findings indicate that the CO₂-responsive TMPDA–SDS–SiO₂ gel system offers promising potential as a novel smart blocking gel system for improving the effectiveness of CO₂ flooding in heterogeneous reservoirs.